This invention relates to a method for acquiring and processing three-dimensional (xe2x80x9c3Dxe2x80x9d) marine seismic data.
Exploration for hydrocarbons under offshore waters is becoming increasingly important. The prospective hydrocarbon reservoir structures that need to be detected are becoming smaller and are more difficult to image on seismic sections and their commercial value is more difficult to establish with standard seismic data quality. The need to mitigate these difficulties translates into a requirement for higher resolving power of the seismic data.
Further, the depth of the waters where the search is conducted is continually growing deeper. As the water depths grow deeper, the costs and risks associated with exploring for and producing the hydrocarbons increases.
Also, new techniques such as directional drilling have allowed several reservoirs to be produced from a single platform. This significantly reduces the costs associated with recovering the hydrocarbons and allows maximum usage of the installed facilities. To effectively drill and complete directional wells into several reservoirs and to optimally produce hydrocarbons from the reservoirs, it is desirable to have as much information as possible about reservoirs and the sediments that overlie the reservoirs. It is desirable to be able to cheaply and effectively collect and process higher resolution seismic data than is typically acquired today. For these drilling and production requirements it is also desirable to increase both the lateral and the vertical resolution of processed seismic data.
Currently, the most common system used to acquire marine three dimensional (3D) seismic data is shown in FIG. 1. A conventional acquisition system 21 utilizes one or more seismic sources 23, such as air guns or waterguns, which radiate sonic energy into the water. These conventional arrays also utilize a group of streamers 25 that are laterally separated from one another, but lie in approximately the same horizontal plane. Located at regular intervals along the length of each streamer are hydrophones 27. Normally, seismic source 23 is fired while source 23 and streamers 25 are being towed through water 29. The sound energy that is produced from source 23 travels downward through water 29 and underlying strata 31. Hydrophones 27 located on streamers 25 collect the seismic signal that is reflected from strata 31 and travels back through water 29 to hydrophones 27. The collected seismic signal is recorded and processed by methods known to the industry.
In general, the vertical resolution of processed seismic data is proportional to the effective bandwidth of the processed seismic signal. Streamer noise can be a major factor in limiting the effective bandwidth of the processed seismic signal. Typically, streamers 25 are towed deeper below the sea surface 33 to minimize the noise and thereby maximize the effective bandwidth of the processed signal. However, as the depth at which streamers 25 are towed increases, the adverse effect of Receiver Signal Ghosts (as hereinafter described) on the processed signal increases. For conventional seismic acquisition and processing, the Receiver Signal Ghosts cause deep notches in the wavelet spectrum of the recorded seismic signal. In practice, no sound energy is typically usable at frequencies greater than the first notch (xe2x80x9cghost notchxe2x80x9d). The approximate frequency where the first notch occurs can be determined by Equation 1 below:
fN=VW/2Dxe2x80x83xe2x80x83Eq. (1)
Where,
fN=Notch frequency
VW=Propagation velocity of sound wave in water
D=Depth of the detector
This frequency (fN) is approximate because an assumption is made that the sound waves are plane waves propagating vertically in the water. Due to the fact that the velocity of sound in water is much lower than the velocity of sound under the seabed, Eq.(1) is generally a good approximation.
As can be seen from Eq.(1), the first notch moves lower in frequency as the streamers are towed deeper, thereby, reducing the effective bandwidth of the processed seismic signal. Therefore, in conventional 3D marine seismic acquisition, the streamers tend to be towed deeper to minimize streamer noise, but this tends to reduce the effective bandwidth of the processed signal and thereby reduces the vertical resolution of the processed seismic signal.
Seismic acquisition techniques have been developed which use xe2x80x9cvertical arraysxe2x80x9d in which the hydrophones are vertically offset from one another, but generally lie in the same plane. For example, U.S. Pat. No. 3,952,281 discloses a method for collecting seismic data from a towed vertical hydrophone array that uses one or more towed seismic streamers that are spaced apart vertically. U.S. Pat. No. 3,952,281 does not disclose a method for collecting 3D marine seismic data using streamers separated both vertically and horizontally.
Techniques have been developed in an attempt to reduce the effect of ghost signals on processed seismic data. For example, U.S. Pat. No. 4,992,992 discloses a method for collecting seismic data from a towed vertical hydrophone array that uses a towed seismic streamer having a slanted orientation in the water. The patent also discloses a method for processing the seismic data to reduce the effect of ghost signals on the processed seismic signal. U.S. Pat. No. 4,992,992 discloses that the recorded data is processed to align the primary signals, thereby misaligning the ghost signals. The patent also discloses that the data is also preferably processed to align the ghost signals, thereby misaligning the primary signals. The patent further discloses that the two resulting data sets may be combined. Unfortunately, it is very difficult to maintain a streamer in a straight slanted orientation while it is being towed through the water. The devices necessary to maintain the streamer in a slanted orientation are difficult to operate and create a large amount of noise that can reduce the quality of the processed seismic signal. This can result in seismic surveys that are expensive to acquire and difficult to process effectively.
U.S. Pat. No. 4,992,991 discloses a method for acquiring marine seismic data that utilizes at least three seismic cables that are towed parallel to the surface of the sea and are located at two different depths. Each of the cables has a plurality of hydrophones spaced along its respective length. The patent discloses that the arrangement of the hydrophones in the seismic array allows the directionality of the wavelets entering the network of cable to be determined and that one advantage of the array is that the actual separation distances of the cables within the network of cables can be controlled for maximum wavelet direction identification. However, the patent does not disclose configuring such a network of cables to acquire high density 3D seismic data. Further, the patent does not disclose any particular methods to use for processing the seismic data acquired and does not disclose any method of processing the acquired seismic data to reduce the effects of Receiver Signal Ghosts on the processed seismic.
For a 3D marine seismic survey, the achievable lateral resolution of the processed seismic is proportional to the areal density of the seismic data acquired. It is generally cheaper and therefore more desirable to acquire high density seismic data using a large number of closely spaced streamers in a single pass seismic acquisition layout, than to acquire that data by making several overlapped passes using a boat towing streamers that are not as closely spaced. However, for a conventional marine 3D seismic acquisition, minimum streamer proximity becomes a key obstacle in shooting high density surveys. Typically, a minimum lateral spacing of at least fifty meters (50 m) between adjacent streamers is desirable to avoid collision or entanglement of the streamers. In general, for a single source seismic design, the minimum achievable subsurface line spacing is about half the minimum streamer proximity. Therefore, in conventional marine 3D seismic acquisition, the minimum achievable subsurface line spacing for a single pass seismic acquisition design is typically about twenty five meters (25 m). In many situations, it is desirable to acquire seismic data that has a subsurface line spacing on the order of twelve and a half meters (12.5 m) or less. However, due to cost constraints and/or situations of timesharing of seismic acquisition boats, it is unacceptable or impracticable to acquire the seismic using multi-pass seismic survey designs.
What is desired is a seismic acquisition method that in a cost effective manner provides seismic data, that can be processed to provide both increased vertical resolution and increased lateral resolution over conventional seismic acquisition methods. Also, what is desired is an acquisition method that improves the efficiency of acquiring 3D marine seismic data by allowing continued acquisition in deteriorating sea states. What is further desired is a method for processing marine 3D seismic data that reduces the effects of Source Signal Ghosts (as hereinafter described) and Receiver Signal Ghosts on processed seismic data.
As used herein, the following terms shall have the following meanings:
(a) xe2x80x9coffsetxe2x80x9d is the horizontal distance from the source-position (or from the center of a source group) to a seismic detector, or more commonly to the center of a detector group measured in the horizontal (x-y) plane. For a vertically staggered source array, the source-position is assumed to be located at a point in the x-y plane directly above the center-point of the stacked elements;
(b) xe2x80x9cin-linexe2x80x9d refers to a line whose axis lies in the horizontal (x-y) plane and lies parallel to the direction in which the 3D seismic data was acquired;
(c) xe2x80x9ccross-linexe2x80x9d refers to the direction in the horizontal (x-y) plane which is perpendicular or nearly perpendicular to the direction in which the 3D seismic data was acquired;
(d) xe2x80x9csubsurface line spacingxe2x80x9d refers to the distance between adjacent subsurface seismic lines, measured in the cross-line direction;
(e) xe2x80x9csubsurface seismic linesxe2x80x9d refer to lines of source-receiver midpoints, when the source-receiver midpoints are projected onto a common x-y plane. The subsurface seismic lines in general lie in the in-line direction;
(f) xe2x80x9cmidpoint(s)xe2x80x9d are the notional points that are located halfway between source and receiver;
(g) xe2x80x9cvertically staggered source arrayxe2x80x9d refers to individual source elements or groups of individual source elements that are positioned so that an element is located at a different vertical location than another element;
(h) xe2x80x9ckxe2x80x9d refers to the spatial wavenumber, or the inverse of the wavelength;
(i) xe2x80x9carealxe2x80x9d shall mean xe2x80x9cpertaining to an areaxe2x80x9d and refers more specifically in this application to measurements that lie in the x-y plane;
(j) xe2x80x9cprimary signalxe2x80x9d and xe2x80x9cdirect sound energyxe2x80x9d refers to that portion of the sound energy that propagates to and from the strata and through the water, without being reflected off the sea surface. An example of a primary signal would be the signal that results from the sound energy traveling ray path F, as depicted in FIG. 4A;
(k) xe2x80x9cSignal Ghostxe2x80x9d refers to a delayed negative representation of the primary signal and is caused by reflection of the sound energy at the sea surface;
(l) xe2x80x9cSource Signal Ghostxe2x80x9d refers to a Signal Ghost which results from the reflection at the sea surface of the source sound energy near the seismic source, as depicted by ray path D in FIG. 4B. For a Source Signal Ghost, the source sound energy reflects off the sea surface before it travels to the strata;
(m) xe2x80x9cReceiver Signal Ghostxe2x80x9d refers to a Signal Ghost which results from the reflection at the sea surface, near the receiver, of the sound energy emerging from the strata, as depicted by raypath E in FIG. 4C;
(n) xe2x80x9cSource-Receiver Pairxe2x80x9d refers to a source at a specific position being recorded in a receiver located in a particular position relative to said source. A seismic recording, or trace, is uniquely defined by the description of the corresponding source receiver pair;
(o) xe2x80x9cCharacteristic Wavelengthxe2x80x9d refers to the wavelength of the fundamental frequency of a pattern, or cycle, that repeats itself across a seismic survey. It should be noted that for a given seismic acquisition design there may be more than one Characteristic Wavelength. The Characteristic Wavelength is measured in feet, meters, or some other unit of length;
(p) xe2x80x9cDMOxe2x80x9d refers to a process that creates apparent common reflection-point gathers by a convolution applied to adjacent common-midpoint gathers, with the feature that the normal moveout for reflectors from a dipping bed no longer depends on the dip angle.
(q) xe2x80x9cWiener filterxe2x80x9d refers to a causal filter which will transform an input into a desired output as nearly as possible, subject to certain constraints. xe2x80x9cAs nearly as possiblexe2x80x9d (in a least-squares sense) implies that the sum of the squares of differences between the filter output and the desired result is minimized.
The invention provides a method for acquiring high resolution 3D marine seismic data using at least two seismic streamers which are generally parallel to one another longitudinally, and offset from one another in both the vertical and horizontal plane. Preferably, the acquisition method uses a vertically staggered source array which is operated using end-fire principles as described below.
The present invention also provides a processing method for reducing the effect of Receiver Signal Ghosts on the processed signal, thereby allowing the seismic array to be towed deeper without reducing the effective bandwidth of the processed seismic signals. Towing the seismic array deeper will greatly reduce the noise. This will lead to methods for acquiring and processing 3D marine seismic having higher vertical resolution, than conventional seismic acquisition and processing methods.
The processing method of the present invention also reduces any unwanted effects stemming from the cyclic signal variations when viewed in the cross-line direction, that result from the acquisition method of the invention.
The present invention allows the seismic acquisition streamers to be towed laterally closer together than would be practicable using conventional acquisition techniques. The invention thereby allows the minimum achievable subsurface line spacing to be reduced and increases the achievable horizontal resolution. This also increases the number of subsurface seismic lines that can be acquired in a single pass acquisition survey, thereby reducing the cost and complexity of acquiring high-density seismic data. It is believed that the current invention will be much more economical than the alternative of acquiring high-density seismic data by an interleaved seismic acquisition design.
In some aspects, a vertically staggered source array is preferably utilized. The use of a vertically staggered source array will provide for the removal of Source Signal Ghosts from the processed seismic and thereby complement the quasi over-under receiver array to synergistically provide for removal of all Signal Ghosts.